Drill bit with distributed force profile

ABSTRACT

A method of making a drill bit for drilling subterranean formations includes forming a first blade having a shape and configuration defined by one or more first parameters and forming a second blade having a shape and configuration defined by one or more second parameters. One of the first parameters is different than one of the second parameters.

PRIORITY CLAIM

This application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Patent Application Ser. No. 61/496,755, filed Jun. 14, 2011, entitled DRILL BIT WITH DISTRIBUTED FORCE PROFILE, and which is hereby incorporated by reference in its entirety.

BACKGROUND

Boreholes in earth formations for the purpose of producing fluids and gasses from earth formations such as for use in the production of oil or other hydrocarbons, or for the purpose of depositing fluids into earth formations, are usually drilled with a drill string that includes a tubular member having a drilling assembly (also referred to as the bottomhole assembly or “BHA”) that includes a drill bit attached to the bottom end thereof. The drill bit is rotated to disintegrate the earth formations to drill the borehole. The BHA also includes devices and sensors for providing information about a variety of parameters relating to the drilling operations and the formation surrounding the borehole. To drill the borehole, fluid pumps are turned on to supply drilling fluid or mud to the drill string. The fluid passes through a passage in the drill bit to the bottom of the borehole and circulates to the surface via the annulus between the drill string and the borehole wall.

As in most endeavors, in the drilling industry it is desirable to drill in an efficient manner. It is known that a drill bit can more efficiently penetrate into a formation when lateral vibrations are reduced. A type of lateral vibration referred to as “bit whirl” or “backward whirl,” is used to describe the center of a drill bit rotating about the center of a borehole in the direction opposite of the rotation of the drill bit and drill string as a whole. This type of vibration has been shown to cause premature wear and damage to the bit. If the center of the drill bit is rotating about the center of the borehole in the same direction and, on average, the same speed as the rotation of the drill bit and string as a whole, the motion is referred to as “forward synchronous whirl.” This type of motion is desirable and is known to cause less damage to the drill bit. A bit that could reduce backward whirl and promote forward synchronous whirl would be well received in the industry.

One type of rotary drill bit is the fixed-cutter bit, often referred to as a “drag” bit. These bits generally include an array of cutting elements coupled to a face region (blade) of the bit body. The bit typically includes several blades distributed generally around a central axis of the bit. A hard, abrasive material, such as mutually bonded particles of polycrystalline diamond, may be provided on a substantially circular end surface of each cutting element to provide a cutting surface. Such cutting elements are often referred to as “polycrystalline diamond compact” (PDC) cutters. In operation, a fixed-cutter drill bit is placed in a borehole such that the cutting elements are in contact with the earth formation to be drilled. As the drill bit is rotated, the cutting elements scrape across and shear away the surface of the underlying formation.

BRIEF DESCRIPTION

According to one embodiment, method of making a drill bit for drilling subterranean formations is disclosed. The method includes: forming a first blade having a shape and configuration defined by one or more first parameters; and forming a second blade, the second blade having a shape and configuration defined by one or more second parameters. In this embodiment, one of the first parameters is different than one of the second parameters.

According to another embodiment, a downhole drill bit that includes a body and a first blade formed on the body and including a plurality of cutters coupled thereto, the first blade having a shape and configuration defined by one or more first parameters is disclosed. The bit of this embodiment also includes a second blade formed on the body and including a plurality of cutters coupled thereto, the second blade having a shape and configuration defined by one or more second parameters on of which is different than one of the first parameters.

BRIEF DESCRIPTION OF THE DRAWINGS

The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:

FIG. 1 depicts a partial perspective view of a drill bit;

FIG. 2 is a top down view of cross-section of a simplified bit within a borehole;

FIG. 3 shows a force profile of a bit according to one embodiment;

FIG. 4 is a cut-away side-view of a blade according to one embodiment;

FIG. 5 shows back rake variations of a cutter; and

FIGS. 6A and 6B are conceptual cross-sectional views of two blades of an exemplary bit and illustrate the effects applying a perturbation to the bit.

DETAILED DESCRIPTION

A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures.

Referring now to FIG. 1, an example of a rotary drill bit 10 is illustrated. The bit 10 includes a shank 20, such as a steel shank, that is coupled to a bit body 12. The bit body 12 includes a crown 14 and a metal blank 16. The crown 14 can be formed, for example, of a particle-matrix composite material.

The bit body 12 is secured to the steel shank 20 by way of a threaded connection 22 and a weld 24 extending around the drill bit 10 on an exterior surface thereof along an interface between the bit body 12 and the steel shank 20. The steel shank 20 includes an API threaded connection portion 28 for attaching the drill bit 10 to a drill string (not shown).

The bit body 12 includes wings or blades 30, which are separated by external channels or conduits also known as junk slots 32. Internal fluid passageways 42 extend between the face 18 of the bit body 12 and a longitudinal bore 40, which extends through the steel shank 20 and partially through the bit body 12. Nozzle inserts (not shown) may be provided at the face 18 of the bit body 12 within the internal fluid passageways 42.

A plurality of PDC cutters 34 may be provided on the face 18 of the bit body 12. In more detail, the PDC cutters 34 may be provided along the blades 30 within pockets 36 formed in the face 18 of the bit body 12, and may be supported from behind by buttresses 38, which may be integrally formed with the crown 14 of the bit body 12.

During drilling operations, the drill bit 10 is positioned at the bottom of a borehole and rotated while drilling fluid is pumped to the face 18 of the bit body 12 through the longitudinal bore 40 and the internal fluid passageways 42. As the PDC cutters 34 shear or scrape away the underlying earth formation, the formation cuttings mix with and are suspended within the drilling fluid and pass through the junk slots 32 and the annular space between the borehole and the drill string to the surface of the earth formation.

In typical drill bits, each blade 30 includes the same or similar configuration. According to embodiments of the present invention, one or more parameters that describe at least one of the blades is different from one or more of the parameters that describe another blade. The parameters can include, for example, the back rakes of the cutters 34, the density of the cutters 34, the number of cutters 34 on the blade 30, the size of the cutters 34, the exposure profile of the cutters 34, and the chamfer sizes on the cutters 34. In one embodiment, parameters can also include an indication of whether a gage cutter is provided on or adjacent the blade 30. In another embodiment the parameters can includes whether or not the blade 30 goes to the center of the bit and the distance between the blade 30 and one or more adjacent blades (e.g., blade density around the bit).

Regardless of the particular parameter that is varied, embodiments of the present invention can include a drill bit 10 that experiences different forces at different locations around it as it is rotated in a borehole. In particular, in one embodiment, a first blade experiences a maximal force while rotated and contacting the formation and all other blades experience, to varying degrees, lesser forces. In one embodiment, these forces are lateral forces experienced in a plane perpendicular to the axis of rotation of the bit. Of course, while forces generally are discussed below, it shall be understood that other factors such a forces could be utilized.

FIG. 2 is a simplified top-down view of a cross section of a drill bit 11 in a borehole 50. The drill bit 11 includes four blades 30 a-30 d but it shall be understood that this is by way of example only and the number of blades can vary from a minimum of two to any number that can practically be formed on the bit body 12 (FIG. 1). The blades 30 a-30 d may be referred to herein as first, second, third and fourth blades, respectively.

In the following discussion, certain conventions will be adhered to. In particular, a first blade 30 a of the drill bit 10 has a first leading edge 50 a. This first leading edge 50 a shall generally define a 0° location on the drill bit 10. The angular displacement from the 0° location increases in the clockwise direction. Each of the other blades 30 b-30 d also includes leading edges 50 b-50 d, respectively. The leading edges 50 a-50 d are so named in this convention because the drill bit 10 is assumed to rotate counter-clockwise. Of course, other conventions could be utilized. For example, in the event that the bit 11 rotates in the clockwise direction, the trailing edge 51 b of the first blade 30 a could generally define the 0° location and angular displacement from the 0° location would increase in the counter-clockwise direction.

FIG. 3 is a graph that illustrates the instantaneous force experienced by the drill bit 10 illustrated in FIG. 2 as it rotates counter-clockwise in borehole 50 as a function of the angular position around the drill bit 11 according to one embodiment. This graph may be referred to as a design curve herein. It shall be understood, however, that the force, rather than force, could be considered and plotted. In such a case, the design curve could be a plot of forces experienced by the drill bit 10.

In the illustrated embodiment, the force experienced at the 0° location is at a maximal value 62. As the angular displacement is increased (e.g., moving clockwise around the bit in FIG. 2) the force falls to a minimal value 60 at an angle γ. From, the minimum value 60, the force then increases back to the maximal value as the position returns to the 0°) (360° location.

The graph shown in FIG. 3 can be translated to high and low force regions 63, 64, respectively, as shown on FIG. 2. In one embodiment, the high force region 63 leads the low force region 64 by about 90°. The region that is in neither the high or low force regions 63, 64 is generally an increasing force region. Embodiments of the present invention are directed to a bit that produces a force as a function of angular displacement similar to that shown in FIG. 3.

Referring again to FIG. 2, in order to achieve the greatest reduction in whirl, the design of a bit 10 may maximize the difference between the maximal value 60 and the minimal value 62. Either one or both of increasing the maximal value 60 and decreasing the minimal value 62 can accomplish this. Whirl can also be reduced by minimizing the area under the design curve 61 while maintaining the maximum value 60. Further, whirl can be reduced by expanding the width of the low force region (W_(L)) while minimizing the width of the high force region (W_(H)). Further, it may be beneficial to translate from the minimal value 62 back to the high value 60 (at 360°) as slowly as possible.

Two concepts in drill bit 10 design deserve further explanation. The first is referred to as the “exposure profile.” In general, the exposure profile is defined by the amount of cutter exposure of each cutter.

FIG. 4 shows a cut-away side view of a single blade 30 and is instructive for explaining the concept of an exposure profile. As above, the blade 30 includes a plurality of cutters 34. The cutters 34 are embedded in or otherwise coupled to the blade 30 such that at least a portion of the cutters 34 extend beyond the blade edge 66. The blade edge 66 is sometimes referred to as a blade line and defines the outer periphery of the blade 30 excluding the cutters 34. The amount by which a particular cutter 34 extends beyond the blade edge 66 is referred to as the cutter exposure. In FIG. 4 the cutter exposure for one of the cutters 34 is shown as distance x. Forming a line tangent to all of the cutters 34 will result in a line that defines the exposure profile 68. It shall be understood that changing the exposure of any one of the cutters 34 will change the exposure profile 68. It shall also be understood that if the amount of all of the cutters are moved either in or out the same amount (i.e., their exposure is changed the same amount), while the shape of the cutter profile 68 may technically be the same shape, such a change results in a different exposure profile because the size of the profile has changed. The cutter profile 68 is an example of a parameter of a blade 30.

Another example of a blade parameter that is illustrated in FIG. 4 is cutter spacing. Cutter spacing is the distance between any two cutters 34. An example of cutter spacing is shown by distance z. As one of ordinary skill in the art will realize, variation of the cutter spacing can change the density of cutters along the blade 30. Thus, each blade can have a density profile that is affected by the distances between the cutters 34.

The amount of back rake of cutters 34 on a blade can also be a parameter of the blade. FIG. 5 illustrates a cutter 34 having three different back rake angles, θ₁, θ₂, and θ₃. The back rack angles θ₁, θ₂, and θ₃ can generally describe the orientation of the cutters 34 in a blade and, in particular, describe an angular offset of a cutting surface of the cutters 34 from vertical.

As shown above, each blade 30 can have several parameters that describe both its shape and the orientation and exposure of cutters 34 in the blade 30. Typically, each blade 30 in prior art bits had the same parameters. According to embodiments disclosed herein, one blade 30 of a bit has one or more parameters that differ from another blade 30 in the bit.

Referring again to FIG. 4, the cutters 34 can be generally grouped into two classifications. The first classification is shown by reference numeral 70 and is referred to herein as “shoulder cutters.” The second classification is shown by reference numeral 72 and is referred to herein as “cone cutters.” Cone cutters 72 are generally located on the bottom (leading face) of the blade 30. Another classification is referred to as nose cutters and are not specifically shown in FIG. 4. The cone 70, nose, and shoulder 72 cutters are separated by the profile angle and radial position (distance from the center) of the bit. The cone cutters 70 are located in the center of the bit. In this region the profile angle is constant (a straight line). Once the profile angle begins to change, the cutters begin to be referred to as “in the nose” or “nose cutters.” Once the profile angle becomes 45 degrees to the horizontal, the cutters are referred to as “shoulder cutters.”

It is assumed that the bit carrying the blade 30 generally travels in a downward direction 74. As such, the bottom of the blade 30 (e.g, the location of the cone cutters 72) is the part of the blade 30 where its face is generally perpendicular to the forward direction and the side of the blade 30 (e.g. the location of the shoulder cutters 70) is the part of the blade 30 where its face is generally parallel to the forward direction 74. It shall be understood that as the orientation of the bit carrying the blade 30 changes, the downward direction 74 will also change to allow, for example, drilling in a direction that is not directly downward from the surface of the earth. The blade 30 can also include one or more gage cutters 76 located generally above the shoulder cutters 70.

FIGS. 6A and 6B illustrate the changes in forces caused by perturbations for certain displacements of the bit. It is assumed that FIG. 6A illustrates an optimal drilling condition. In more detail, FIGS. 6A and 6B illustrate the area of cut of cutters 34 in two opposing blades 30 a, 30 c of a drill bit when the borehole centerline 80 and the bit centerline 82 are aligned (FIG. 6A) and out when they are not (FIG. 6B). It shall be understood that the unaligned configuration (FIG. 6B) resembles the situation when whirl is occurring. In FIGS. 6A and 6B the area of cut of particular cutter 34 is shown by the shaded regions 84 on each cutter 30. In this example, the bit is drilling into a formation 88 in forward direction 74.

In FIG. 6A, the area of cut for the cone cutters 72 is generally greater than the depth of cut of shoulder cutters 70. When the bit is perturbed (FIG. 6B) the shoulder cutters 70 on the third blade 30 c and the cone cutters 72 on the first blade 30 a have an increased area of cut and, therefore, experience an increase in force. The cone cutters 72 on the third blade 30 c and the shoulder cutters 70 on the first blade 30 a have a decreased area of cut and, therefore, experience a decrease in force. In terms of bit design and the design curve 61 illustrated in FIG. 3, the observations made from FIGS. 6A and 6B indicate that bits having longer cone designs are beneficial to forward synchronous rotation. That is, if there is an increase in the total area of cut by all the cone cutters 72, the bit may be less likely to experience whirl. Further, cone cutters 72 in the high force region (e.g., on the first blade 30 a) encourage the stability of forward synchronous rotation. In addition, FIGS. 6A and 6 b indicate that shoulder cutters 70 and gage cutters 76 outside the high force region discourage stability of forward synchronous rotation.

The above observations can lead to various bit configurations. For example, these observations may indicate that it can be beneficial to vary the back rake of the cutters across the blades of the bit such that the back rake is generally proportional to the force profile illustrated by the design curve 61 of FIG. 3. High back rakes in the high force region will be more aggressive and, therefore, produce more force. The converse is true in the low force regions. In addition, the cutter chamfer sizes across the face of the bit can be varied. In addition, it may be advantageous to vary the blades density across the face of the bit proportional to the force profile. The closer the blades are spaced the more force they produce in a given region. The converse is true for large blade spacing. Further, in the high force regions of the bit, it may be beneficial for the blades to go to the center of the bit and not reach the center in lower force regions. Such a configuration can have two effects. The first is that by putting the blades to center in the high force region additional force is generated in that region because of the increased number of cutters. In addition, having blade that go to the center in the high force region will increase resistance to backward whirl. Further, the cutter density across the face of the bit can vary proportionally to the design curve. For example backup cutters could be utilized in the high force region to both increase the force generated in the region and to produce more durability. In one embodiment, as many gage cutters as desired can be used in the high force region, but they may be limited elsewhere. In addition, if a bi-centric bit design is used, the longer blades should be encouraged where in the high force region and discouraged in the low force region.

It shall further be understood that while the above description is directed to bits having blades, the teachings herein could be applied to drag bits that do not include blades. In such a case, forces/torques around the face of the bit could be calculated and used to design and/or improve the dynamic behavior (whirl resistance). In such a case, the bit can be divided into portions.

While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited. Moreover, the use of the terms first, second, etc. do not denote any order or importance, but rather the terms first, second, etc. are used to distinguish one element from another. Furthermore, the use of the terms a, an, etc. do not denote a limitation of quantity, but rather denote the presence of at least one of the referenced item. 

1. A method of making a drill bit for drilling subterranean formations, comprising: forming a first blade, the first blade having a shape and configuration defined by one or more first parameters; and forming a second blade, the second blade having a shape and configuration defined by one or more second parameters; wherein one of the first parameters is different than one of the second parameters.
 2. The method of claim 1, wherein the one of the first parameters is a back rake profile of cutters on the first blade and the one of the second parameters is a back rake profile of cutters on the second blade.
 3. The method of claim 1, wherein the one of the first parameters is a density of cone cutters on the first blade and the one of the second parameters is a density of cone cutters on the second blade.
 4. The method of claim 1, wherein the one of the first parameters is a density of shoulder cutters on the first blade and the one of the second parameters is a density of shoulder cutters of the second blade.
 5. The method of claim 1, wherein the one of the first parameters is an exposure profile of cutters on the first blade and the one of the second parameters is an exposure profile of cutters on the second blade.
 6. The method of claim 1, wherein the first blade is formed such that it experiences higher force while being rotated in a borehole than the second blade.
 7. The method of claim 1, further comprising forming a third blade having a shape and configuration defined by one or more third parameters.
 8. The method of claim 7, wherein the first blade is formed such that it experiences higher force while being rotated in a borehole than the second blade and the third blade.
 9. The method of claim 8, wherein the third blade is formed such that it experiences higher force while being rotated in a borehole than the second blade and such that, measured in the clockwise direction around the bit, is further away from the first blade than the second blade is from the first blade.
 10. A downhole drill bit comprising: a body; a first blade formed on the body and including a plurality of cutters coupled thereto, the first blade having a shape and configuration defined by one or more first parameters; and a second blade formed on the body and including a plurality of cutters coupled thereto, the second blade having a shape and configuration defined by one or more second parameters, one of the second parameters being different than one of the first parameters.
 11. The downhole drill bit of claim 10, wherein the one of the first parameters is a back rake profile of the cutters coupled to the first blade and the one of the second parameters is a back rake profile of the cutters coupled to the second blade.
 12. The downhole drill bit of claim 10, wherein the cutters are cone cutters and wherein the one of the first parameters is a density of the cone cutters coupled to the first blade and the one of the second parameters is a density of the cone cutters coupled to the second blade.
 13. The downhole drill bit of claim 10, wherein the cutters are shoulder cutters and wherein the one of the first parameters is a density of the shoulder cutters coupled to the first blade and the one of the second parameters is a density of the shoulder cutters coupled to the second blade.
 14. The downhole drill bit of claim 10, wherein the one of the first parameters is an exposure profile of the cutters coupled to the first blade and the one of the second parameters is an exposure profile the cutters coupled to the second blade.
 15. A method of making a drill bit for drilling subterranean formations, comprising: forming a first portion of the drill bit, the first portion having a shape and configuration defined by one or more first parameters; and forming a second portion of the drill bit, the second portion having a shape and configuration defined by one or more second parameters; wherein one of the first parameters is different than one of the second parameters.
 16. The method of claim 15, wherein the first portion is formed such that it experiences higher force while being rotated in a borehole than the second portion.
 17. The method of claim 15, further comprising forming a third portion having a shape and configuration defined by one or more third parameters.
 18. The method of claim 17, wherein the first portion is formed such that it experiences higher force while being rotated in a borehole than the second portion and the third portion.
 19. The method of claim 18, wherein the third portion is formed such that it experiences higher force while being rotated in a borehole than the second portion and such that, measured in the clockwise direction around the bit, is further away from the first portion than the second portion is from the first portion. 